1. Field of Invention
The present invention relates generally to oilfield fluid diversion systems and methods, and more specifically to fluid diversion measurement systems and methods that may use a pre-job design that may be executed and evaluated in realtime to ensure treatment fluid is efficiently diverted in a reservoir.
2. Related Art
It may be appreciated that stimulation diversion processes and systems have been in use for years. Typically, stimulation diversion processes and systems are comprised of downhole production logging tools (PLT), radioactive tracers with gamma ray detection tools and fiber optic strings measuring distributed temperature. These measurements in the PLT usually have single pressure, single flow meter, gamma ray and temperature. The data from these downhole tools are realtime when an electric cable and/or fiber optic fiber is connected inside the coiled tubing string, or in memory mode when the data is collected after the job.
The main problems with conventional stimulation diversion processes and systems are that interpretation of the measurements, whether gathered in realtime or delayed, may be difficult. In most cases, interpretation will come hours after the data is collected. If the telemetry system is not hardwired to the surface, the delay time/data time to the surface also becomes a hardship on timing for interpretation. Another problem with conventional stimulation diversion processes and systems is that the measurements were not designed to provide a qualitative answer to the service that is being performed. One of the many services is flow diversion of fluid into a reservoir section of a well. Another problem with conventional stimulation diversion processes and systems is that they were never designed to run on the end of oilfield tubulars such as coiled tubing. This is especially true for the logging tool flow meters which are designed to be run on the end of cable. This makes them vulnerable to damage. Existing systems also typically use a wired cable in the coiled tubing that increases weight while decreasing reliability.
While existing processes and systems may be suitable for the particular purpose to which they address, they are not as suitable for processes that may use a pre-job design that may be executed and/or evaluated in realtime to ensure treatment fluid is efficiently diverted in a reservoir. Previously known processes' and systems' use of multiple sensors and/or measurements were typically not strategically placed or adapted for flow measurements in coiled tubing and/or drill pipe.
In terms of the types of flowmeters, spinners are commonplace for measuring downhole flowrates, profiling flow velocities across the flowpath, and determining the phase distributions if multiple phases are present. Spinners are known to be fragile in certain circumstances and are prone to blade breakage, bearing damage, and jamming by foreign objects. This is especially true in ‘barefoot’ well completions where the wellbore may not be smooth. Debris accumulation on the low side of the hole may damage or even destroy a spinner. FIG. 1 illustrates schematically a horizontal well, 12, having low-side debris accumulation 14. Therefore, because of the vulnerability of the mini-spinners it is worthwhile considering alternative technologies that could replace them within the stimulation and treatment environment. Indeed, even though the risk of damage in the stimulation application is lower than the production logging application, an alternative type of flowmeter may be worth evaluating.
Electromagnetic flowmeters for the measurement of the velocity of conducting fluids are commercially available. Increasingly they are becoming available for less conducting fluids despite the technical challenges. The electromagnetic flowmeter principle is described in relation to FIG. 2. The operation of electromagnetic flowmeters is based on Faraday's law of electromagnetic induction. Electromagnetic flow meters (sometimes referred to as magnetic flowmeters, or simply magmeters) measure the velocity of fluids in a pipe, and if the pipe cross-sectional area is known then they may measure the volumetric flowrate. Full-bore magmeters usually comprise a non-magnetic pipe 16 lined with an insulating material (not illustrated). Electromagnetic coils (not illustrated) create the required B-field and a pair of electrodes 17, 18 penetrate the pipe and its lining as illustrated schematically in FIG. 2. As a fluid flows through the magnetic field (B) generated by the coils, a voltage (E) is developed across electrodes 17, 18. The voltage will be proportional to the velocity (V) of the liquid. Usually, as the magnetic field density and the pipe diameter are fixed values, they are converted into a calibration factor (K) giving a simple relationship between voltage and fluid velocity:E=K×V Magmeters may measure flow in both directions, as reversing fluid direction will change the polarity but not the magnitude of the signal. Magnetic flowmeters may detect the flow of clean, multi-phase, dirty, corrosive, erosive, or viscous liquids and slurries as long as their conductivity exceeds the minimum required for the particular design. The expected accuracy and range of the better designs are from 0.2-1% of rate, over a range of 10:1 to 30:1, if the flow velocity exceeds 1 ft/sec [31 cm/sec]. At slower flow velocities (even below 0.1 ft/s [0.3 cm/sec]), measurement error increases, but the readings remain repeatable, which is key for logging tool applications. Originally, magmeters could detect the flow of conductive fluids only. Early magmeter designs required a minimum fluidic conductivity of 1-5 microsiemens per centimeter for their operation. The newer designs have reduced that requirement a hundredfold to between 0.05 and 0.1 microsiemens, and maybe now much lower.
Insertion type electromagnetic flowmeters may be built and such a meter is illustrated schematically in FIGS. 3A and 3B. The relationship between the magnetic field, induced voltage and fluid velocity must respect Faraday's law as illustrated schematically in FIG. 3A. A plan view, FIG. 3B, is illustrated schematically and its symmetry ensures a similar response to a fluid flowing in either direction.
Use in insulating fluids is feasible but design challenges are much greater due to the high source impedance, triboelectric (‘static charge’) voltage noise and a mean impedance linked gain function (therefore mixing-law dependent). The equation then becomes:E=G(K×V)where G is a function of the mean mixture dielectric constant. Meters such as this have been considered for application to surface flow measurements, for example U.S. Pat. No. 4,920,795 to Dowell Schlumberger discusses an electromagnetic flowmeter for conductive or dielectric fluids and its applications in oilfields in particular, but the product did not develop due to technology limits then present. General magmeter designs may use capacitive electrodes which permit function with insulating deposits (e.g. an oil film) but would usually need a modulated magnetic field and therefore require an electromagnet to generate the B-field which could impose strength limitations due to coil design/size and current limitations.
From the above it is evident that there is a need in the art for improvement in monitoring oilfield fluid diversion systems and methods.